In order to remove SO2 from gaseous streams, it is known to utilize a regenerable process with aqueous monoamine or diamine absorbents. The diamine is exposed to a gas stream to absorb SO2 from the gas stream and to produce an SO2 lean treated gas stream and a spent absorbent steam containing amine SO2 salts. The amine SO2 salts are decomposed in the regenerator tower of the process to gaseous SO2 and the corresponding free base amine under the elevated temperature and the action of stripping steam traveling up the regeneration column, countercurrent to the rich amine flowing downwards. However, the salts of strong acids such as sulfuric, nitric or hydrochloric acid (referred to herein as heat stable salts or HSS) are too stable to decompose under these conditions. If allowed to accumulate, it is known that these heat stable salts would eventually completely neutralize the SO2 absorption capacity of the amine absorbent, stopping the proper functioning of the process. Therefore, as it is known in the art, means for removal of heat stable amine salts are either installed as a part of the process or available on demand.
Accordingly, it is known in the art that a regenerable absorbent for a given acid gas impurity is chosen so that the salt formed by the acid gas with the alkaline absorbent is of moderate strength. See for example, U.S. Pat. Nos. 5,019,361 (Hakka), which discloses the use of a diamine absorbent having an amine with a pKa in the range of 4.5–6.7 and U.S. Pat. No. 5,292,407 (Roy et al). Such a salt, which is generally formed by absorption at 25–70° C., can dissociate into the original acid gas (e.g. SO2) and the alkaline absorbent upon raising the temperature in a standard steam stripping process. By use of a so-called regeneration or stripping tower, wherein the acid gas laden absorbent, i.e. an alkaline absorbent containing the acid gas-absorbent salt, flows downward countercurrent to a flow of steam, the salt is dissociated and the acid gas component is carried overhead with the flow of steam. An overhead condenser is generally utilized to condense most of the steam so that it can be recycled to process as reflux, thereby helping to maintain the water concentration of the absorbent constant. The absorbent in the base of the regeneration tower has been regenerated and is then again suitable for being recycled to an absorber tower for absorption of additional acid gas in the absorber tower.
A suitable indicator for an appropriate choice of absorbent to use for the capture of a given gaseous acid gas contaminant is the difference in the pKa values between the acid gas and the absorbent. The pKa of an acid is defined as the negative logarithm to the base 10 of the equilibrium constant Ka for the ionization of the acid HA, where H is hydrogen and A is a radical capable of being an anion:HAH++A−  (1)Ka=[H+][A−]/[HA]  (2)pKa=−log10 Ka  (3)
For a basic absorbent B, the pKa is for the ionization reaction of the conjugate protonated acid of B, the species BH+:BH+=B+H+  (4)
The reaction involved in the capture of the acid gas contaminant HA by the basic absorbent B is:HA+BBH++A−  (5)
It can be shown that the logarithm of the equilibrium constant of Reaction 5 is given by the expressionΔPKa=(pKa of the basic absorbent)−(pKa of the acid gas)  (6)
For Reaction 5 to have the appropriate balance of absorbing the acid at relatively low temperatures of 25–70° C. and being regenerable at 100–110° C., the ΔpKa in Reaction 6 is significant. With respect to the instant invention, the ΔpKa is preferably in the range 1 to 3. Since these are logarithmic units, the equilibrium constant ranges from 10 to 1000.
According to the current knowledge in the art, two conditions must be satisfied if the absorbed acid in the loaded absorbent can be removed by steam stripping regeneration. Firstly, the salt must be unstable enough to decompose at the regenerator temperature and secondly, the acid gas must be volatile so that it can go overhead with the steam and be physically separated from any absorbent in the overhead off gas stream. If a strong acid contaminant with a pKa more than 3 units smaller than the absorbent pKa is present in the feed gas being treated, or if such is formed in the process through chemical reaction, then the salt formed is so stable that it does not decompose easily at the regenerator temperature and the salt is termed a heat stable salt.
Most gas treating processes can experience a buildup of HSS. In the removal of hydrogen sulfide and carbon dioxide from refinery hydrocarbon streams for example, contaminants such as hydrogen cyanide (which can form thiocyanate, SCN−), formic acid, acetic acid and oxygen (which can lead to the formation of thiosulfate) can be present. In regenerable sulfur dioxide (SO2) scrubbing, sulfuric acid (H2SO4) or its anhydride, sulfur trioxide (SO3) are usually present. These acids are so much stronger than the acid gas being removed that they form non-regenerable HSS in the absorbent.
If these HSS are allowed to accumulate, they will eventually totally neutralize the absorbent so that it no longer is able to capture the acid gas as intended. Therefore in systems where HSS occurs, either continuous or intermittent HSS removal is required. Accordingly, it is known in the art to operate to maintain the HSS level in monoamine acid gas absorbents as low as practical to maintain the scrubbing capacity of the process and in particular below one equivalent per mole.
For example, Abry et al (U.S. Pat. No. 5,993,608) discusses the removal of acid components such as CO2 and H2S from natural gas. At column 2, line 37, Abry states that “If the residual buildup of heat-stable salts (HSS) is permitted to build to typical levels in excess of 1% by weight, the amine performance will decline, corrosion increases rapidly with a decline in pH, and the amine solution begins to foam, creating excessive process liquid losses . . . ”.
Audeh (U.S. Pat. No. 5,393,505) relates to a process for rejuvenating a spent aqueous alkanolamine subsequent to its use to sorb an acid gas selected from the group consisting of CO2, H2S or both. Part of the process is to remove inorganic ions from the spent alkanolamine solution. At page 4, lines 14–16, the disclosure states that “The ion concentration in the alkanolamine after the ion removal step are preferably as low as possible.”
Roy et al (U.S. Pat. No. 5,292,407) relates to a process for converting HSS to heat regenerable salts. At column 8, lines 17–24, Roy states that “When the absorbent comprises a diamine, such as for sulfur dioxide absorption, the level of heat stable salts in the regenerated absorbent is typically less than about 1 equivalent of heat stable salt per mole of diamine, preferably less than about 0.8 equivalent per mole of diamine and, more preferably, from about 0.1 to 0.6 equivalents per mole of diamine in order to provide absorption capacity to the first amine group in salt form.”
Hakka (U.S. Pat. Nos. 5,019,361) relates to the removal of SO2 from a gas stream using an aqueous absorbing medium containing a water-soluble half salt of a diamine. As set out at column 9, line 65-column 10, line 6, after the absorption step, the aqueous absorbing medium is treated in a desorption step “. . . to provide a regenerated absorbing medium containing amine salt absorbent having at least one nitrogen as an amine salt and at least one free sorbing nitrogen. The salt often is at least one of sulphate, chloride, thiosulfate, dithionate, trithionate and pyrosulfite. Advantageously, at least about 90 mole percent, preferably essentially 100 mole percent, of the amine salt absorbent has at least one nitrogen in the salt form in the regenerated absorbing medium”. The implication of the preceding is that one nitrogen, the sorbing nitrogen, should be in the free base form and not tied up as a heat stable salt. Accordingly, the rejuvenated aqueous absorbing medium would contain less than 1 equivalent per mole of diamine absorbent of HSS. Further, in Example 3, the synthetic absorbing medium is prepared with 0.96 equivalents of heat stable salt per mole of diamine, again leaving the second, sorbing nitrogen in the free base form.